This paper discusses mobility control in the Joffre Viking field miscible CO 2 flood. Since 1984, three injection strategies have been tried: water-alternating-C0 2 (WAC0 2 ), continuous CO 2 , and simultaneous CO 2 and water. The studies showed that simultaneous injection results in the best CO 2 conformance. COrfoam injection has also been investigated.

With the VAPEX process, combinations of vaporized solvents are injected into heavy oil and bitumen reservoirs for in situ recovery of the oil. The oil is diluted with the solvent, which reduces the viscosity so the oil drains by gravity to a horizontal production well. The VAPEX process has the potential to greatly reduce the greenhouse gas emissions for oil sands and heavy oil recovery since it is a non-thermal process that does not require the reservoir to be heated with, for example, steam. The Petroleum Recovery Institute (PRI) was the operator of a joint industry project of 16 participants with nine research performing organizations. During 1998, the project investigated the full project engineering and commercial scale economics for the VAPEX process. The supply cost economics for VAPEX oil production from the Athabasca oil sands, Cold Lake oil sands and Southeast Alberta heavy oil were determined. The work indicated that VAPEX has attractive economics and helped to define the critical field operations design issues that need to be addressed prior to proceeding with a substantial field pilot. The climate change advantages of the VAPEX process are described in the paper along with an overview of the integrated physical model, numerical simulation, facilities design, well specifications, production, transportation, and marketing work which led to calculation of the supply cost economics. Introduction The VAPEX (vapor extraction) process(1) is a non-thermal process that uses vaporized solvents that are injected into heavy oil or bitumen reservoirs. The solvent dissolves in the oil at the natural reservoir temperature, reducing the viscosity of the oil, which will then readily flow by gravity to a horizontal production well(2). The concept is described in several Canadian and USA patents(3, 4). As shown in Figure 1, twin horizontal wells are used for the recovery process. VAPEX gas is injected into the upper well where it dissolves in the oil, which then drains to the lower producer. The development of the VAPEX technology is shown pictorially in Figure 2. Since the initial patent in 1978, there has been basic and applied research and invention(2). In 1998, the PRI operated a project called "Development of Full Project Engineering and Economics for the VAPEX Process," with 16 participants and nine research performing organizations. The project continued in 1999 with Phase 2 for VAPEX operations design on "How to Operate VAPEX in the Field," which included conceptual design of two VAPEX pilot plants for an oil sands application and a heavy oil reservoir application with underlying water. The VAPEX process has several potential advantages and disadvantages for commercial scale economic oil production. The potential advantages are: no steam generation; no water processing/ recycle; lower fuel costs; greater energy efficiency; lower carbon dioxide emissions; may be advantageous in thin reservoirs or with bottom water, and potential in situ upgrading. The potential disadvantages are: solvent compression, solvent losses and potential sensitivity to reservoir heterogeneity. The advantages and disadvantages are reiterated in Tables 1 and 2.

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The Underground Test Facility (UTF) Demonstration Project was started in 1984 and the first two phases have been completed. The UTF Project current Phase B-2 is proceeding with the testing of the tunnel drilled Steam Assisted Gravity Drainage (SAGD) wells. The UTF Project is producing about 320 cubic metres per day (m 3 /d) [2,000 barrels per day (BPD)] of dry bitumen which is trucked to market. The higher than predicted bitumen sales revenue has been reinvested into the project and these extra funds are being used to drill and operate SAGD wells from the surface.This paper provides some important concepts for using SAGD well pairs drilled from the surface to produced bitumen on a commercially viable basis in the Athabasca Oil Sands.The expansion demonstration program consists of drilling and completing from the surface, two 750 m SAGD horizontal well pairs, to produce an additional 320 m3ld. This will increase bitumen production from the UTF Project to 640 m 3 /d (4,000 BPD).:Key features covered are surface drilling and completion of long horizontal wells, steam injection and monitoring, well production control, surface facilities for producing dry bitumen and getting the product to market. The design and operating aspects of a 4,800 m 3 /d (30,000 BPD) commercial project are reviewed. Project costs and economics favour surface drilled horizontal wells over wells drilled from underground tunnels.The purpose of this new SAGD technology is to economically develop the 140 billion cubic metres (900 billion barrels) of oil-in-place in the Athabasca oil sands region of Alberta. Of these, more than 50 billion cubic metres (330 billion barrels) are now recoverable using the SAGD technology.The nine industry participants in the UTF project own about 50% of oil sands leases in Athabasca, hence the high level of interest in developing new technologies to extract the bitumen.There are other major factors which need to be provided in order to commercially develop this resource.The paper also outlines the requirements for oil sands development in Athabasca and discusses nurturing the expansion of existing USA heavy oil markets, building a heavy crude oil pipeline from Athabasca region to Edmonton and taking advantage of new technologies such as SAGD to significantly reduce capital and operating costs. The Underground Test Facility (UTF)The purpose of the UTF is to test the concept of in situ bitumen extraction using the Steam Assisted Gravity Drainage (SAGD) process. 36The key features of the current UTF Project are shown in Figure 1. It consists of two vertical shafts 3.3 m in diameter penetrating 140 m of overburden, 20 m of oil sands and 15 m of limestone below which are located horizontal tunnels 5 m wide and 4 m high. The tunnels are in solid limestone and are larger where the wells are located (8 m wide x 5 m high) and smaller (4 m wide x 3 m high) where the tunnels serve only to complete the access and ventilation circuit. From the tunnel walls, horizontal wells are drilled upwards through the limestone and then horiz...

This paper will review the history of in situ pilot plant efforts towards the recovery of bitumen from the major oil sand deposits of Alberta. The review will be based on published information and will describe the location of the plants, the manner of operation, the estimated costs involved and the technical area under investigation. The currently operating pilot plants and future plans for new in situ pilots will also be described. INTRODUCTION This paper will present a survey of the planned, current and completed in situ pilot plant operations in the Alberta Oil Sands. The aim of the review is to provide an overview of the current field projects and to provide background concerning completed in situ pilot plant programs. Before beginning a consideration of the individual plants it is necessary to set the stage for the review by looking at some of the problems and formation properties which are encountered in the Alberta on Sands. Note that the term bitumen, tar and heavy oil are used interchangeably in this paper to describe hydrocarbon material with gravity less than 12 °API. The oil sands of Alberta, as shown in Figure 1, are located in four major deposits which cover an area of about 10.8 million acres in the northern half of the province. The total in place reserves are estimated to be 950 billion barrels(1) of which, 74 billion barrels or 8% of the total are covered by less than 150 feet of overburden and are considered suitable for economic surface mining. The surface mineable reserves are all located within the Athabasca deposit as indicated by the heavily shaded area in Figure 1. The amount of in place bitumen which has more than 500 feet of overburden and must be recovered by in situ methods is 10 times the surface mineable reserves; 741 billion barrels or 78% of the deposit. The remainder, 135 billion barrels are overlain by 150–500 ft. of overburden and it is uncertain at this time whether the heavy oil in these sands will be recovered by some form of mining or by novel in situ recovery methods. The consideration of the depth of the deposits points out the need for development of in situ recovery techniques in order to tap the majority of the reserves in the Alberta Oil Sands. RESERVOIR PROPERTIES The Alberta Oil Sand Reserves are situated in the Mannville Group of the Lower Cretaceous strata. All the oil sand deposits are quite heterogeneous, both laterally and vertically, with wide variations in oil, water and gaseous content. Some of the average oil sand formation properties are shown in Table 1. The Athabasca deposit has the largest in place reserves; 626 billion barrels or 66% of the total. The Cold Lake deposit is next largest with 164 billion barrels followed by the Wabasca and Peace River deposits. The Athabasca deposit is the only one inwhich the oil sand outcrops at the surface.